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IOSR Journal of Applied Geology and Geophysics (IOSR-JAGG)

e-ISSN: 2321–0990, p-ISSN: 2321–0982.Volume 4, Issue 6 Ver. II (Nov-Dec. 2016), PP 36-47

www.iosrjournals.org

DOI: 10.9790/0990-0406023647 www.iosrjournals.org 36 | Page

Formation Evaluation of an Onshore Oil Field, Niger Delta

Nigeria.

*1Leonard I. Nwosu, and

2Doris N. Ndubueze

1.Department of Physics, University of Port Harcourt, Nigeria.

2.Department of Physics,Michael OkparaUniversity of Agriculture Umudike, Nigeria.

Abstract: The formation evaluation of an onshore oil field has been carried out. Suite of geophysical logs

comprising gamma ray, resistivity, density and neutron from five oil wells were used. Alternation of sandstone

and shale lithologies were delineated within the interval logged which is typical of the Agbada Formation in the

Niger Delta. A total of five reservoirs (W400, W500, W600, W700, W800) were observed in the five. The

hydrocarbon fluid types were differentiated with the aid of density and neutron logs ran on the same track. The

topmost reservoir (W400) is dominated by gas while the other reservoirs are mainly oil bearing. The computed

average porosity and water saturation of the reservoirs ranges from 0.19 to 0.227 and 0.19 to 0.286

respectively. The permeability of the reservoirs ranges from 516 to 1662 mD.The Net to Gross ratio for the five

reservoirs varies from 0.844 to 0.947. The computed values of the petrophysical parameters show that the five

reservoirs have very good to excellent quality and the field has a good hydrocarbon potential.

Keywords:Formation Evaluation; Porosity, Permeability, Reservoir, Niger Delta.

I. Introduction Geoscientists use wireline logging to acquire a continuous record of rock formation's physical and

chemical properties in boreholes. Some of these properties are density, gamma ray, resistivity, interval transits

time and the size of boreholes. Other formation properties such as hydrocarbon saturation, permeability, net to

gross ratio, formation porosity and shale volume are derived from the measured properties (Telford et al., 1990;

Rider, 1986).These measured and derived properties are very important in the hydrocarbon industry. Most

decisions on oil exploration and production are based on the results of derived properties of the reservoir.

Geophysical logs are also used for correlating zones of interest across boreholes and for structural isopach

mapping, the identification of geological formations, formation fluids, correlation between wells, evaluation of

the productive capabilities of reservoir formations (Picketh, 1970; Ekine and Iyabe, 2009; Asquith and

Krygowski, 2004).Many researchers have worked on the petrophysical analysis of different oil fields using

geophysical logs in the Niger Delta (Adeoye and Enikauselu, 2009;Aigbedion and Iyayi, 2007; Imaseum and

Osaghae, 2013 and Omoboriowo, 2012). There will be a continuous improvement of the petrophysical analysis

technology because of its importance in the oil industry. The objectives of this research are to delineate and

evaluate reservoir and petrophysical properties in five oil wells.

II. Summary of The Geology of the Study Area The studied area is located in parts of the onshore zone in the Niger Delta sedimentary basin, Nigeria

(Fig. 1). Niger Delta is the youngest sedimentary basin within the Benue Trough system. Its development began

after the Eocene tectonic phase. The thickness of the basin ranges between 10-12km and it is made up of deltaic

and shallow marine sediments mainly supplied by rivers Niger and Benue (Doust and Omatsola, 1990).

Three distinguished lithostratigraphic units namely Akata, Agbada and Benin Formations are present in the

Niger Delta. The Akata Formation is predominantly marine shales and it is the main source rock in the basin

(Stacher,1995; Kulke, 1995; Klett et al., 1997). The Akata formation is over pressured and it is overlain by the

paralic sand/shale sequence of the Agbada Formation. The Agbada Formation is the main reservoir rock in the

Niger delta. The Benin Formation is the topmost lithostratigraphy and it is a continental deltaic sands. The Niger

Delta basin is characterized with shale diapirs, growth faults and associated rollover anticlines. Both structural

and stratigraphy traps are common in the basin (Doust and Omatsola, 1990; Ekweozor and Daukoru, 1994).

Formation Evaluation of an Onshore Oil Field, Niger Delta Nigeria.


Fig. 1: Map of Niger Delta showing the Location of the studied Area

III. Materials And Methods The materials used for this work are suite of well log data from five wells. The logs were acquired for

Agip Nigeria Oil Development Company by Schlumberger. The physical properties of the rocks penetrated by

the borehole were measured by a sonde, which is lowered down the borehole on a multiconductor electric cable.

The various physical properties were measured as the sonde is drawn up to the surface of the earth. The value of

the measurement is transmitted through the cable and plotted continuously against depth in the well on a

magnetic tape in a recording unit. The composite logs include; gamma ray, density, neutron and deep resistivity.

The gamma ray log measures the natural radioactivity of the formation and so it was used for differentiating

shale and sand lithologies. The density log records the bulk density of the formation while the resistivity log

measured the resistivity of the formation and so it was used for identifying fluid type. The petrophysical

parameters needed for the formation evaluation were computed from the measured physical properties. The

research methodology adopted for this work involves:

Determination of Porosity

Porosity can be determined from the density, neutron and sonic individually. In this work, porosity was

computed from the density log. The porosity is derived from the formula:

max

max

b

Dfl

1

where

ℓmax =density of rock matrix = 2.65 g/cm3

ℓb = bulk density from log (g/cm3)

D

= total Porosity from the Density log



ℓfluid = density of fluid occupying pore spaces (0.4g/ cm3 for gas, 0.9g/ cm

3for oil and 1.0 g/ cm

3 for water).

The porosity can be presented in fraction or percentage. The matrix density is obtained from core grain density

computed from routine core analysis in the Niger Delta. The fluid densities are obtained from literature and they

correspond with the values used in the basin.

Determination of shale volume

Hydrocarbon reservoir in most cases are associated with shale content. The volume of shale in a reservoir is

derived from gamma-ray log. The gamma ray derived shale volumes are computed using the following

formulas:

log min

max min

GR

GR GRI

GR GR

2

where,

IGR = gamma ray index

GRlog = gamma ray reading of formation from log

GRmin = minimum gamma ray (clean sand)

GRmax = maximum gamma ray (shale)

The volume of shale was calculated from the gamma ray index by using the Larionov equation for tertiary

rocks:

3.70.083 1.02 GR

X

sh

IV 3

where,

Vsh = volume of shale

IGR = gamma ray index.

Determinationof Net- To-Gross

Measure of the productive part of a reservoir is expressed either as a percentage of the producible (net) reservoir

within the overall (gross) reservoir packages or sometimes as a ratio. Net-to-Gross can vary from just a few

fraction to 1. It could be expressed as:

Net-to-Gross = Net Thickness * 100% 4

Gross Thickness

where,

Net Thickness = Gross thickness – Shale thickness

Estimation of water and Hydrocarbon saturation

Determination of water saturation is essential in formation evaluation. The hydrocarbon saturation in the

reservoir is normally calculated from the water saturation. The water saturation is obtained from deep resistivity

log by using the formula:

√

5

where

Sw = water saturation

Ro = resistivity of the reservoir 100 percent saturated with saline water.

Rt = resistivity of the reservoir

The hydrocarbon saturation is the fraction of pore volume in a formation occupied by oil and gas. It is obtained

by subtracting the computed water saturation in a reservoir from 1. The hydrocarbon saturation is given as:

6

where

Sw = water saturation

Sh = hydrocarbon saturation

Determination of Permeability

Several researchers have proposed various empirical relationships with which permeability can be estimated

from porosity and irreducible water saturation. One of such relations was adopted in this work to estimate the

permeability of the delineated reservoirs. The permeability equation is given as:

K = (79*Φ3/Swirr)

2 for Gas 7



and

K = (250*Φ3/Swirr)

2 for Oil 8

where

K = permeability,

ɸ = porosity

Swirr = irreducible water saturation

IV. Results And Discussion The qualitative interpretation of the gamma ray log revealed mainly alternation of sandstone and shale

lithologies in the studied area. This is an indication that the depth range logged in the boreholes are within the

Agbada Formation in the Niger Delta. Five reservoirs W400, W500, W600, W700 and W800 were identified

and delineated from the gamma ray and resistivity logs. The correlation of four of the reservoirs in the five

wells are shown in Figures. 2, 3, 4 and 5.



Fig. 2: Correlated Reservoir W400 across the Five Well



Fig. 3: Correlated Reservoir W500 across the Five Wells



The depth to top and thickness of the reservoirs vary from one well to the other. The plotting of the

density and neutron logs on the same track was used for differentiating the hydrocarbon type in the reservoirs.

The fluid distribution plot in the five reservoirs for the five wells are shown in Figures 6 -10 . The gas, oil and

water in the reservoir are denoted with red, green and blue colours respectively. The average petrophysical

parameters computed for each reservoir in the five wells are shown in Table 1. Reservoir W400 is saturated

mainly with gas in well 1,4 and 5 while well 3 has both gas and oil and well 2 contain only oil. Reservoirs

W500, W600, W700 and W800 contain mainly oil and water. The results of the petrophysical analysis show that

the computed porosity for the five reservoirs varies from 0.19 to 0.227. The porosity decreases with depth and

this can be attributed to compaction of the sediments.The result shows that the porosity of the reservoirs vary

from good to very good. The average Net to Gross (NTG) for the reservoirs ranges from 0.844 to 0.947 which is

an indication of a good quality reservoirs. The shale content in the reservoirs is minimal and the sandstone

content is high. The calculated average water saturation for the reservoirs varies from 0.19 to 0.286 which

implies that the hydrocarbon saturation varies between 0. 714 – 0.81. Hydrocarbon saturation in the reservoirs is

very high. The computed average permeability ranges from 516 to 1662 mD. The average permeability of the

reservoirs can be classified as very good to excellent.

Fig. 6: W400 Reservoir Fluid Distribution Plot for the five wells

Fig. 7: W500 Reservoir Fluid Distribution Plot for the five wells



Fig. 8: W600 Reservoir Fluid Distribution Plot for the five Wells.

Fig. 9 : W700 Reservoir Fluid Distribution Plot for the five wells

Figure 4.25:W800 Reservoir Fluid Distribution Plot



Table 1: Average Petrophysical Parameters Calculated for the Reservoirs Av porosity NTG AV Sw Av Perm

U4000 0.227 0.844 0.286 1662

U5000 0.206 0.947 0.26 812.00

U6000 0.203 0.90 0.27 516.00

U7000 0.198 0.90 0.28 665.00

U8000 0.203 0.88 0.19 725

V. Conclusion

Formation evaluation is very crucial in reservoir studies. The results of the formation evaluation show

that the studied oil field is characterized by alternation of sand and shale lithology. Five reservoirs were

delineated and correlated across the five wells. Most of the reservoirs are oil bearing. The computed average

porosity, water saturation, NTG and permeability are 0.20, 0.26, 0.89 and 827.67respectively. The reservoirs

have very good and excellent petrophysical qualities. The studied oil field has good hydrocarbon potential. The

results of the study have shown the importance of geophysical logs in hydrocarbon exploration and production.

Acknowledgement The authors wish to acknowledge Shell Petroleum Development Company (SPDC), Nigeria and the Department

of Petroleum Resources (DPR), Nigeria for making the data available.

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